1. Field of the Invention
The invention relates generally to a tool for directional drilling of a wellbore. More specifically, this invention relates to a smart clutch for transmitting a desired degree of rotational energy from a drill string to a directional assembly.
2. Background Art
Directional drilling involves varying or controlling the direction of a wellbore as it is being drilled. Usually the goal of directional drilling is to reach or maintain a position within a target subterranean destination or formation with the drilling string. For instance, the drilling direction may be controlled to direct the wellbore towards a desired target destination, to control the wellbore horizontally to maintain it within a desired payzone or to correct for unwanted or undesired deviations from a desired or predetermined path.
Thus, directional drilling may be defined as deflection of a wellbore along a predetermined or desired path in order to reach or intersect with, or to maintain a position within, a specific subterranean formation or target. The predetermined path typically includes a point where initial deflection occurs and a schedule of desired deviation angles and directions over the remainder of the wellbore. Thus, deflection is a change in the direction of the wellbore from the current wellbore path.
It is often necessary to adjust the direction of the wellbore frequently during directional drilling, either to accommodate a planned change in direction or to compensate for unintended or unwanted deflection of the wellbore. Unwanted deflection may result from a variety of factors, including the characteristics of the formation being drilled, the makeup of the bottomhole drilling assembly and the manner in which the wellbore is being drilled.
Deflection may be measured as an amount of deviation of the wellbore from the current wellbore path and expressed as a deviation angle or hole angle. Commonly, the initial wellbore path is in a vertical direction. Thus, initial deflection often signifies a point at which the wellbore has deflected off vertical. As a result, deviation is commonly expressed as an angle in degrees from the vertical.
Various tools and techniques may be used for directional drilling. First, the drill bit may be rotated by a downhole motor which is powered by the circulation of drilling fluid (“mud”) supplied from the surface and converts the flow into rotational energy, the mud flow otherwise being used to cool the drill bit and lift drill cuttings out of the wellbore. Such motors are often used in a technique, sometimes called “slide drilling”, that is typically used in directional drilling to effect a change in direction of the wellbore, such as the building of an angle of deflection.
Current technology normally employs steerable motors, wherein a combination of rotary and slide drilling to be performed. Rotary drilling will typically be performed until such time that a variation or change in the direction of the wellbore is desired. The rotation of the drilling string is typically stopped and slide drilling, employing the bend in the downhole motor, is commenced. Although the use of a combination of slide and rotary drilling may permit satisfactory control over the direction of the wellbore, problems and disadvantages associated with slide drilling are still encountered. Because the drilling string is not rotated during slide drilling, it is therefore prone to sticking in the wellbore, particularly as the angle of deflection of the wellbore from the vertical increases, resulting in reduced rates of penetration of the drilling bit.
With each of the aforementioned techniques, orientation of the motor housing can often be difficult to maintain, because as the drill bit contacts the earth formations to drill them, a reactive torque is generated against the motor housing which changes the orientation.
More recently, rotary steerable systems have been developed for connection in the bottom hole assembly of a drill string which comprise a number of hydraulic actuators spaced apart around the periphery of the unit. Each of the actuators has a moveable thrust member or pad which is hydraulically displaceable outwardly for engagement with the formation of the borehole being drilled. The rotary steerable system also includes a selector apparatus which, when actuated, causes each of the moveable thrust members to be displaced outwardly at the same selective rotational position, which biases the drill bit laterally and thus controls the direction of drilling.
A more recently developed rotary steerable system, disclosed in U.S. Pat. No. 6,216,802, issued to Donald M. Sawyer, utilizes an asymmetrically weighted collar (“AWC”) to maintain a desired orientation of a drilling assembly. In this type of system, a first and second driveshaft are coupled within the housing of the directional drilling apparatus.
FIG. 1 shows one embodiment of a prior art rotary steerable system as it is used to directionally drill a wellbore through earth formations. The wellbore 2 is shown as has been drilled through the earth formations 4. The wellbore 2 can be drilled using a rotary drill bit 30 of any type known in the art.
As is well known in the art, rotary power to turn the drill bit 30 can be provided by a drilling rig (not shown) or the like located on the earth's surface. The drilling rig is typically coupled to the drill bit 30 by a drilling assembly which includes sections of threaded drill pipe, one section of which is shown at 6. As is also well known in the art, the drill pipe 6 can include, generally at the bottom end, larger diameter, high-density sections known as “heavy-weights” or “drill collars” which increase the bottom-end weight of the drilling assembly so that earth's gravity can assist in providing axial force to the drill bit 30. A drilling assembly which includes only drill pipe 6, collars, the bit 30, and centering tools known as stabilizers, shown generally at 8 and 28, will follow a trajectory affected by gravity, the flexibility of the drilling assembly and the mechanical properties of the earth formations 4 through which the well is drilled. The rotational axis (not shown) of the drill bit 30 in such drilling assemblies is substantially coaxial with the center line 10 of the drilling assembly, not taking account of any flexibility of the drilling assembly.
Directional drilling systems, such as described herein, cause the rotational axis (not shown) of the drill bit 30 to be deflected from the center line (rotational axis) 10 of the drill pipe 6 in a selected direction. Thus, a prior art rotary steerable system, shown generally at 32 and for convenience referred to hereafter as a “steering system”, provides a mechanism to place the axis of rotation of the drill bit 30 along such a selected direction.
The principal components of the steering system 32 may include an orientation collar, shown as 16 in FIG. 1. The purpose of the orientation collar 16 is to provide a rotationally fixed reference against which to set an axis of rotation of the drill bit 30, as will be further explained. In this embodiment, the orientation collar 16 is an AWC, which includes bearings 12, 18 and 20 to enable free rotation, within the orientation collar 16, of an upper driveshaft 14 and a lower driveshaft 24. As will be further explained, the orientation collar 16 is asymmetric in mass radially or circumferentially about its axis (that is, it is rotationally unbalanced) so that one side of the orientation collar 16 will tend to rest downwardly, that is, in the direction of gravity. The asymmetry of the mass of the orientation collar 16 in this embodiment provides one element of the steering system 32 which is substantially rotationally fixed during drilling.
Rotary torque can be transmitted from the drilling rig (not shown) at the earth's surface directly to the bit 30 through the steering system 32. The upper driveshaft 14 is coupled at one end to the drill pipe 6. The upper driveshaft 14 can be flexibly coupled to the lower driveshaft 24 by means of a universal joint, flexible coupling, constant velocity joint or any similar flexible rotary connection, shown generally at 22, which enables transmission of rotary torque across a change in direction of the axis of rotation. The upper driveshaft 14 rotates substantially collinearly with the drill pipe 6 immediately connected thereto because it is held in position relative to the collar 16. The lower driveshaft 24 can be coupled through lower stabilizer 28 to the bit 30, through a mud motor (not shown) or any other drilling tools.
In the steering system 32, the orientation of the axis of rotation of the lower driveshaft 24 with respect to the center line 10 of the orientation collar 16 is generally changed by changing the position of the center of the lower bearing 20 with respect to the center line 10 of the orientation collar 16. The orientation of the axis of rotation of the lower driveshaft 24 will thus be determined by the relative position of the lower bearing 20 with respect to the center line 10 of the orientation collar 16.
With respect to the example shown in FIG. 1, while the adjuster for setting the position of the lower bearing 20 is fixed, in another aspect of the steering system 32, an adjuster which can be operated while the steering system 32 is in the wellbore 2 can also be used. Mechanisms for translating and rotating the sliding sleeve with respect to the collar 16 are known in the art. Gears, hydraulic actuation or other means may be used.
Adjustments to orientation can be configured using control circuits well known in the art, to be responsive to measurements from a measurement-while-drilling (MWD) system (not shown) forming part of the drilling assembly, or to be responsive to drilling mud pressure-based command signals sent from the earth's surface. Such remotely operable adjusters make possible both wellbore trajectory adjustments during drilling, and trajectory maintenance settings where the center of rotation of the lower bearing 20 is set to be axially parallel with the center line 10 of the orientation collar 16, so that the extant trajectory of the wellbore 2 will be maintained.
The orientation collar 16 and components running through it are shown in more detail in FIGS. 2 and 3. In FIG. 2, the collar 16 can include a case 16A which can be a steel pipe or the like preferably being cylindrically shaped and having an outside diameter comparable to that of the drill pipe (6 in FIG. 1), connected to the upper driveshaft 14. For example, if the portion of the drill pipe (6 in FIG. 1) connected to the upper driveshaft is a 6.75 inch (171.45 mm) O.D. “heavy weight” or “drill collar”, then the case 16A preferably has the same 6.75 inch (171.45 mm) outside diameter to maintain overall stability of the drilling assembly. The upper driveshaft 14, as well as the lower driveshaft 24 typically include a centrally located passage or bore 14A through which the drilling mud can flow.
The inner diameter of the case 16A, although its actual dimension is not critical, should preferably be selected to provide a space 14B for the bearings 12, 18, 20 between the inner diameter of the case 16A and the outer diameter of the driveshafts 14, 24. The inner diameter of the case 16A should also be as small as is practical, as should be the outside diameter of the driveshafts 14, 24, to enable the mass of the collar 16 to be as large, and as asymmetric about the axis of rotation as possible, consistent with the need for adequate bending stiffness of the driveshafts 14, 24 and of the overall drilling assembly, and consistent with the driveshafts 14, 24 having the capacity to transmit adequate rotary torque to the bit (30 in FIG. 1) without breaking.
The case 16A includes therein a high specific gravity section, shown generally at 16B. The high specific gravity section 16B is shown as subtending about half the total circumference of the case 16A, but it should be understood that the amount of the circumference subtended by the high specific gravity section 16B is a matter of convenience for the system designer. The actual shape of the high specific gravity section 16B is also a matter of convenience. A cross-section of the collar 16, including the case 16A, the high specific gravity section 16B and a corresponding low specific gravity section 16C, is shown in FIG. 3. The high specific gravity section 16B can be formed, for example, by filling the part of the case 16A with very dense materials such as lead, depleted uranium or the like. The low specific gravity section 16C may be merely enclosed air space, but preferably includes filling that portion of the case 16A with a low density, relatively incompressible material, such as oil or aluminum for example, so that the case 16A will resist crushing under hydrostatic pressure in the passage 14A and in the wellbore (4 in FIG. 1). The high specific gravity section 16B will tend to rest in the direction of gravity, providing a rotationally fixed reference against which to set the position of the lower bearing 20 with respect to the center of the collar 16. As previously explained, setting the position of the center of the lower bearing 20 at a known location from the center of the orientation collar 16 provides an axis of rotation for the lower driveshaft 24 which is different from the axis of rotation of the upper driveshaft 14 and which is oriented in a known, selected direction with respect to the known rotational reference, i.e. earth's gravity.
Additional features which may reduce the tendency of the orientation collar 16 to be rotated by friction between the driveshafts (14, 24 in FIG. 1) and the collar 16 are shown in FIG. 4. In one such improvement, the low specific gravity section 16C, which may be filled with a solid such as aluminum, for example, can include spiral passages 17 therethrough that can be hydraulically connected to the passage (14B in FIG. 2). Fluid inertia of the mud flowing in the spiral passages 17 can reduce the tendency of the orientation collar 16 to rotate away from its gravitational orientation.
Another such improvement includes helically spaced-apart vanes or fins 19 disposed on the exterior of the case 16A so that fluid flow up the annulus (2 in FIG. 1) will tend to stabilize the rotational position of the collar 16.
Still another improvement may comprise jets 21 formed through the collar 16 which interconnect the passage (14B in FIG. 2) and the annulus (4 in FIG. 1) and which have a discharge direction such that drilling mud discharged through the jets 21 will create a thrust tending to oppose fluid-friction induced rotation of the collar 16 in the direction of rotation 23 of the drill pipe (6 in FIG. 1).
Still another example of an improvement to the case 16A used to resist rotation of the case 16A while drilling is shown in FIG. 5. The case 16A includes in the heavy weight section 16B a sprag 19A which can be extended by gravity so that friction teeth 21 disposed on the outside of the sprag 19A can contact the wall of the wellbore. Lateral movement of the sprag 19A can be limited by pins 23 that are disposed in cavities 25 and mesh in mating slots 27 in the sprag 19A. The sprag 19A shown in this example is actuated by gravity, but it should be clear to those skilled in the art that powered forms of actuation for the sprag 19A, such as hydraulic cylinders, solenoids, springs or the like can also be used to extend the sprag 19A laterally from the case 16A.
The preceding embodiments of the orientation collar 16 rely on earth's gravity to orient the collar 16. As previously explained, the orientation of the collar 16 is used as a fixed reference against which to set the position of the bearing supporting the lower driveshaft (20 in FIG. 1). By setting the position of the lower bearing 20 with respect to the collar 16, the magnitude and direction of the angle of the second driveshaft can be set with respect to the center line of the collar 16. In one embodiment of the collar 16, the collar 16 need not include asymmetric mass but can have its relative orientation determined by means other than earth's gravity.
FIG. 6 shows one embodiment of a prior art anti-rotational element. This embodiment includes a cylindrical housing 52 including fingers 54 attached by a hinge 56, or similar apparatus, so that the fingers 54 may extend radially from the housing 52 in one direction. The extension of the fingers 54 from their retracted state (not shown) may be facilitated by the rotation of the housing 52 in a particular direction so that centrifugal force may cause extension, leading to contact of the fingers 54 with the wellbore 2. The housing 52 also includes An opening 50 for the passage of fluids, once the housing 52 is included as a component of a drilling system. Contact of the fingers 54 with the wellbore 2 will prevent and/or retard rotation of the housing 52 as well as any attached components of the drilling system, in a particular direction, depending on the orientation of the housing in the drilling system. This and other anti-rotational elements are disclosed in U.S. Pat. No. 6,273,190, issued to Donald M. Sawyer, and hereby incorporated by reference.
Although AWCs, as described above, are effective mechanisms for orienting a directional drilling device, their use need not be limited to rotary steerable devices. Accordingly, there exists a need for a directional drilling system that relies on proven technologies while maintaining a desired control of the wellbore trajectory using an AWC. Furthermore, there exists a need for a directional drilling system that is able to compensate for the reactive torque encountered during drilling, thereby maintaining a desired trajectory of the drill string.